NREL is a national laboratory of the U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, operated by 

The Value of Ene

for Grid Applicati(Report Summary

Paul Denholm, Jennie Jorgenson, Mar

Thomas Jenkin, and David Palchak, N

Renewable Energy Laboratory

Brendan Kirby, ConsultantOokie Ma, U.S. Department of EnergyMark O’Malley, University College Du

May 2013

NREL/PR‐6A20‐58703
Project Overview

• This report is one of

a series stemming f

U.S. Department of Energy (DOE) Dema

Response and Energy Storage Integratio

• This study is

a multi

‐national

‐laboratory 

assess the potential value of demand reand energy storage to electricity system

different penetration levels of variable 

resources and to improve our understan

associated markets and institutions.

• This study was originated, sponsored, a

managed jointly by the Office of Energy and Renewable Energy and the Office o

Electricity Delivery and Energy Reliabilit
Analysis Goals

• Understand the value of energy stora

providing multiple grid services

• Evaluate differences in system value 

vertically integrated utility versus in a 

environment
Approaches to Valuing Energy 

• Market‐price‐based simulation

• Dispatch against historic market prices• Relatively easy• Cannot evaluate change in generation m

• Grid simulation

• Uses production cost simulations to eval

with and without storage

• Can evaluate any desired generation mix

etc.

• Can be expensive and time consuming
Examples of Market‐Price Simu

Market Evaluated Location Years 

Evaluated

Annual Value ($/kW) Assumptions 

Energy Arbitrage PJMa 2002–2007 $60–$115 12 hour, 80% efficient device. 

evaluated. Also considers price in a market setting using price/

NYISOb 2001–2005 $87–$240 (NYC)

$29-$84 (rest)

10 hour, 83% efficient device. evaluated. 

USAc 1997–2001 $37–$45 80% efficient device. Evaluate

CAd 2003 $49 10 hour, 90% efficient device.

CAf 2010–2011 $25–$41 4 hour, 90% efficient device.

CAh 2011 $46 16 hour, 75% efficient pumped 

Regulation Reserves

NYISOb 2001–2005 $163–$248

USAe 2003–2006 $236–$429 PJM, NYISO, ERCOT, ISO-NE

CAf 2010–2011 $117–$161 Co-optimized arbitrage and reg

from regulation.

Contingency Reserves

USAe 2004–2005 $66–$149 PJM, NYISO, ERCOT, ISO-NE

Combined Services CAf 2010–2011 $117–$161 Arbitrage and regulation, most 

regulation.

CAh 2011 $62–$75 Arbitrage, regulation, and cont

constraints of pumped storage

USAg 2002–2010 $38–$180 Arbitrage and contingency. CA

a Sioshansi et al. 2009b Walawalkar et al. 2007c Figueiredo et al. 2006 d Eyer et al. 2004e Denholm and Letendre 2007f Byrne and Silva-Monroy 2012g Drury et al. 2011h Kirby 2012
Examples of Grid Simulation A

Location Model NotesWestern Interconnectiona

PROMOD Evaluates arbitrage and renewable energy balancing 

services for a variety of devices in various locations throughout the Western Interconnection.

Mauib PLEXOS Evaluates several storage technologies providing 

operating reserves and arbitrage/time-shifting. Consid

changes in fuel use and renewable curtailment.

MISOc PLEXOS Preliminary analysis of storage, identified challenges i

simulating both day-ahead and real-time markets in a large system. 

MISOd PROSYM Evaluated a proposed compressed air energy storage 

project in Iowa.

a Kintner-Meyer et al. 2012b Ellison et al. 2012c Rastler 2011 d Black and Veatch 2005
Our Approach

• Use a commercial production cost mo

(PLEXOS)

• Evaluate differences in production co

storage to obtain system value

• Evaluate “market revenue” using mar

prices produced by the model
Test System

• Two balancing areas in Colorado/Wyoming (wanted a relatively 

isolated system to examine small differences)

• Used publicly available data from Transmission Expansion Polic

Committee (TEPPC) 2020 model

• Data includes plant capacities, heat rates, outage rates (planne

and several operational parameters, such as ramp rates

• Generator database was modified to include part‐load heat rat

Western Wind and Solar Integration Study Phase II (WWSIS II) s

• Total of 201 thermal and hydro generators

• Start‐up costs were added using the start‐up fuel requirements 

database plus the operations and maintenance (O&M) related 

estimates prepared for the WWSIS II study

• Adjusted the generator mix to achieve a generator planning res

15% by adding a total of 1,450 MW (690 MW of combustion tur760 MW of combined cycle units)
General Characteristics

System Capacity (MW)

Coal 6,157Combined Cycle (CC) 3,988Gas Turbine (CT)/Gas Steam 4,259Hydro 777Pumped Storage 560Wind 3,347 (10.7 TWH)Solar PV (AC Rating) 878 (1.8 TWH)Othera 513

Total 15,793

• Wind/solar provide ~16% energy• Gas averages ~$4.1/MMBTU
Reserves

• Contingency based on Comanche III (Rocky Mou

Reserve Sharing Group Rules)

• Regulation reserves based on variability of net 

• Only regulation up in these simulations• 5 minute ramp product• Range 77‐166 MW, average of 120 MW – 1.3% avg 

• Flexibility reserves based on variability of net lo

time frame

• Only flex up in these simulations• 20 minute ramp product• Didn’t do 5‐minute dispatch to capture actual deplo• Range 15‐85 MW, average of 57 MW – 0.6% avg loa

• Total spinning requirement averages 582 MW o

of average load
Additional Reserve‐Related Modif

• TEPPC database has no restrictions on what 

provide reserves

• Pumped Hydro Storage (PHS) plants could cycle 

of output

• No costs for providing regulation reserves

• Modifications

• CTs cannot provide regulation reserves• PHS added 40% minimum generation point• PHS added 70% regulation point (we are curren

tracking separate up and down so need to prov

symmetric operation

• Only 60% of remaining units (as measured by ra

provide regulation (based on PLEXOS database California Independent System Operator)
Assumed Cost of Regulation Re

Generator Type Cost ($/MW-h)Supercritical Coal 15Subcritical Coal 10Combined Cycle (CC) 6Gas/Oil Steam 4Hydro 2Pumped Storage 2

Cost of non steady‐state operation

Equivalent to a regulation bid price in a restructured

market
Results – Contingency Spin Pric

• Avg =$6.3/MW‐hr• For comparison, 2011 average market clearing 

$7.4/MW‐hr in NYISO, $2.8/MW‐hr in MISO, an

$7.2/MW‐hr in CAISO

05

10152025303540

0 1000 2000 3000 4000 5000 6000 7000 8000

Spinning Reserve Marginal Price

($/MW‐hr)

Hour

CAISO (Market)NYISO (Market)Test System (Simulation)MISO (Market)
Results – Regulation Reserve P

• Avg = $16.1/MW‐hr

• For comparison 2011 average market clearing 

$11.8/MW‐hr in NYISO, $10.8/MW‐hr in MISO, 

$16.1/MW‐hr in CAISO

05

1015202530354045

0 1000 2000 3000 4000 5000 6000 7000 8000

Regulation  Reserve Marginal Price

($/MW‐hr)

Hour

CAISO (Market)Test System (Simulation)NYISO (Market)MISO (Market)
Storage Devices

• Energy Only

• 75% AC‐AC efficiency• No minimum generation, ramp constraints• 8 hours• Base device is 300 MW

• Reserves Only

• Can provide 100% of rated capacity as any rese• Make‐up energy assumes 25% energy throughp

efficiency

• Base device is 100 MW

• Energy + Reserves

• PLEXOS co‐optimizes provision of energy or res

depending on whatever service minimizes syste

production cost
Results – Price/Load Relationship

Feb

July 19‐21

05

1015202530354045505560

0

1,0002,0003,0004,0005,0006,0007,0008,0009,000

10,000

0 12 24 36 48 60 72

SystemMarginal Price ($/MWh)

Net Load (MW)

Hour

System NetLoadSystemMarginal Price

0

1,0002,0003,0004,0005,0006,0007,0008,0009,000

10,00011,00012,00013,000

0 12 24 36 48 6

Net Load (MW)

Hour
Results – Storage Dispatch (Energy

Fe

July 19‐21

0

102030405060

0

50

100150200250300350

0 12 24 36 48 60 72

SystemMarginal Price ($/MWh)

StorageGeneration  (MW)

Hour

StorageGenerationSystemMarginal Price

0

50

100150200250300350

0 12 24 36 48 6

StorageGeneration  (MW)

Hour
Results – Net Load (Energy)

Febr

July 19‐21

‐300‐200‐100

0

100200300400500600700

4,0004,5005,0005,5006,0006,5007,0007,5008,0008,5009,000

0 12 24 36 48 60 72

StorageGeneration (MW)

Net Load  (MW)

Hour

System NetLoadNet Load withstorageStorageGeneration

3,0004,0005,0006,0007,0008,0009,000

10,00011,00012,00013,000

0 12 24 36 48 60 

Net Load  (MW)

Hour
Results – Fuel/Generation

Base Case With Storage 

(300 MW)

Generation (GWh)Coal 46,134 46,375 

Hydro 3,792 3,792 

Gas CC 14,761 14,947 Gas CT 1,024 763 

Other 103 89 

Existing Pumped Storage 1,054 1,050 

New Storage - 465 

PV 1,834 1,834 Wind 10,705 10,705 

Total Generation (GWh) 79,407 80,020 

Fuel Use (1,000 MMBtu)

Coal 488,140 490,930 

Gas 126,651 124,728 

Total Fuel 614,719 615,658 
Results – Change in Production Costs (300 MW 

Base Case With Storage 

(300 MW)

Total Fuel Cost (M$) 1,210.5 1,204.7 Total Variable Operations and Maintenance Cost (M$) 152.1 152.8 Total Start Cost (M$) 58.2 52.8 Total Regulation “Adder” Cost (M$)

4.7 4.8 

Total Production Cost (M$) 1,425.6 1,415.1 

~50% of value from avoided starts

Price taker value ‐ $8.5 million

Market value ‐ $5.2 million
Results – Value as a Function of Si

0

1020304050607080

0 200 400 600 800 

Storage Value ($/kW of Storage Capacity)

Storage Size (MW)

System ValueSystem Value (CuIncremental SysteMarket ValueMarket Value (CuIncremental Mark
Results – Sensitivities

Scenario Annual 

Value ($/kW)

Increfor a Devic

Base 300-MW Device 34.9 Remove Existing Pumped Storage 48.4 Increase Efficiency from 75% to 90% 47.1 Double Natural Gas Prices 56.1 Remove Existing Pumped Storage and Double Natural Gas Prices 79.3 
Results – Capacity Value

Assume a storage plant with 8 hours of capacity is

functionally equivalent to a CT for capacity planning purpo
Results – Breakeven Cost (Operational V

0

100200300400500600700800900

Base

Device

(300 MW)

IncreasedEfficiency

No PHS Double

Natural

Gas Price

2X NG and

No PHS

Breakeven capital cost for an8‐hour

storage device ($/kW) 

Simplified breakeven cost determined bydividing annual value by a fixed charge rate
Results – Breakeven Cost (Operational + Capa

Uses same operational value as previous slide + capacity

cost of a new CT

Low = $724 Mid = 1151 High =$1,578/kW

800

10001200140016001800200022002400

Base

Device

(300 MW)

IncreasedEfficiency

No PHS Double

Natural

Gas Price

2X NG and

No PHS

Breakeven capital cost for an8‐hour

storage device ($/kW) 
Results –100 MW Reserves Only Devic

Energy Only

Spinning 

Contingency 

Only Regula

Generation (GWh)

Coal 111 114 Hydro 0 0 Gas CC 24 -79 -Gas CT -65 -59 Other -10 -3 Existing Pumped Storage 3 -59 Battery 175 0 Regulation Make-Up* PV 00 Wind 00 

Total Generation 237 -85 -Fuel Use (1,000 MMBtu)

Coal 1,240 1,151 1Gas -736 -1,571 -2Regulation Make-Up* 00

Total Fuel 505 -420 

A positive number indicates an increase, while a negative number indicates a decrease relative to the base case.* Make-up energy is real energy that would actually be derived from a mix of coal- and natural-gas-fired generators but w

simulation. The make-up fuel is estimated based on multiplying the total generation by an average heat rate of 9,000 BT
Results – Reserves Device (Producti

Cost Component

Change In Operational Cost (Million 

Compared to Case Without Addition

Storage

Energy Only

Spinning 

Contingenc

y Only

Regula

n On

Total Fuel Cost -3.3 -6.8 -8.5

Total O&M Cost 0.3 0.2 0.3Total Start Cost -1.5 0.1 0.1Total Regulation “Adder” Cost 0.0 -0.1 -4.3Regulation Make-Up Energy Cost* 0.0 0.0 1.4Total Production Cost -4.4 -6.5 -11.0

A positive number indicates an increase, while a negative number indicates a decrease relative to the * Valued derived outside the production simulation.
Results – Reserves Device (Value)

Annual Value 

Scenario Spinning 

Reserves

Re

R

Base 100-MW Device 65.2 Reduced Size (50 MW) 83.8 Remove Existing Pumped Storage 68.3 Double Natural Gas Prices 148.1 Remove Existing Pumped Storage and Double Natural Gas Prices 164.8 
Difference Between System and Mark

Spinning Reserves

Annual Value ($/kW)

Scenario System Market50-MW Device 83.8 51.5

Scenario Regulation Reserves Annua

Value ($/kW)

System Market

First 50 MW 136.9 113.4Next 50 MW 82.6 6.3
0

200400600800

10001200140016001800200022002400

Spin Reg Spin Reg Spin Reg Spin Reg Spin Reg

Base

Device

(100 MW)

50 MW No

Pumped

Storage

DoubleNatural

Gas Price

2X Gas

Price and

No Pump.

Storage

Breakeven capital cost fora reserves‐

only  storage device ($/kW) 

Results – Breakeven Cost (Ope

Simplified breakeven cost determined bydividing annual value by a fixed charge rate
Results – Breakeven Cost (Operational + Cap

100014001800220026003000340038004200

Spin Reg Spin Reg Spin Reg Spin Reg Spin Re

Base

Device

(100 MW)

50 MW No PHS Double

Natural

Gas Price

2X NG an

No PHS

Breakeven capital cost fora reserves‐

only storage device ($/kW) 

Uses same operational value as previous slide + capacity

cost of a new CT

Low = $724 Mid = $1,151 High =$1,578/kW
Co‐Optimization

• Considered two devices

• Same device as previous without restrict

flexibility

• Constrained device with a 40% minimum 

level (used to approximate the performa

pumped storage device)

• Considered two operating modes

• No reserves while charging• Both spin and regulation reserves while 

charging and discharging
Co‐Optimization Results

• Limited arbitrage value prevents device from providing

energy services

• Adding the ability to provide reserves while charging

increases system benefits

Annual V

Scenario No 

Reserves 

While 

Charging

Base Case 114.5 Restricted Flexibility Case (Similar to Pumped Storage) 54.0 

40% minimum

generation point restricts

reserves sales
Next Steps

• Impacts of increased renewables

• Sub‐hourly dispatch

• Can storage aid in addressing forecast er• Can new rules enhance storage value? (m

payments)

• Distributed storage
Learn MoreDownload the full report at:

http://www.nrel.gov/docs/fy13osti/58465

Denholm, P.; Jorgenson, J.; Hummon, M.; Jenk

Palchak, D.; Kirby, B.; Ma, O.; O'Malley, M. (20

Energy Storage for Grid Applications. TP‐6A20‐

Golden, CO: National Renewable Energy Labor